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Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures

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A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Energy Systems".

Deadline for manuscript submissions: closed (24 October 2024) | Viewed by 12626

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Dr. Liu Yang

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State Key Laboratory for Tunnel Engineering, China University of Mining and Technology, Beijing 100083, China
Interests: carbon dioxide geological storage; phase field simulation from transport in porous media; capillary imbibition
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Dr. Haitao Zhang

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Department of Hydraulic Engineering, Tsinghua University, Beijing 100084, China
Interests: multiphysics process in energy geomechanics
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Dr. Yanjun Zhang

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College of Petroleum Engineering, Xi’an Shiyou University, Xi’an 710065, China
Interests: integration of hydraulic fracturing and enhanced oil recovery; interwell-fracturing interference
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Dr. Bo Wang

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School of Petroleum, China University of Petroleum-Beijing at Karamay, Karamay 834000, China
Interests: hydraulic fracturing; fracture propagation simulation
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Dear Colleagues,

Multiphase flows and phase-change phenomena are often encountered in many engineering systems, such as CCUS (carbon capture, utilization and storage); the exploitation of oil, natural gas and other underground resources; the utilization of geothermal energy and hydrogen energy, etc. Multiphase flows refer to the interactive flow of distinct phases, and each phase discriminated by common interfaces in a channel represents a mass or volume of matter. Multiphase flows can occur in a single-component or multi-component systems. Possible phase combinations include:

Solid–liquid–gas, where solid particles and gas bubbles are mostly dispersed in the liquid;
Solid–gas, solid–liquid, and liquid–gas, where the volume fraction of one phase is relative to other results for different flow regimes;
Phase change and miscibility phenomena involved in a combination of the above.

Understanding the fundamentals and mechanisms of multiphase transport and phase-change phenomena is continuously needed to develop the relevant technology of engineering applications.

You may choose our Joint Special Issue in Materials.

Dr. Liu Yang
Dr. Haitao Zhang
Dr. Yanjun Zhang
Dr. Bo Wang
Guest Editors

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Keywords

phase change
interphase coupling
multiphase transport

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Published Papers (11 papers)

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22 pages, 4616 KiB

Open AccessArticle

A Study on the Mechanism and Influencing Factors of Interlayer Injection–Production Coupling in a Heterogeneous Sandstone Reservoir

by Wei Zheng, Kai Wang, Jing Li, Juanzhe Jiang, Chenyang Tang, Yufei He, Yuqi Guan and Junjian Li

Processes 2024, 12(9), 2054; https://doi.org/10.3390/pr12092054 - 23 Sep 2024

Viewed by 443

Abstract

To solve the development problems caused by the geological characteristics of heterogeneous sandstone reservoirs, such as uneven interlayer exploitation, a method for improving uneven interlayer exploitation differences by applying interlayer injection–production coupling technology is proposed. A physical model of interlayer injection–production coupling is elaborated in detail, and its mechanism of enhancing oil recovery is analyzed. The reservoir physical property parameters are measured, and a productivity numerical model for the two-phase flow of oil–water was established based on measurement results. Then, the effectiveness of interlayer injection–production coupling was evaluated. The results showed that the mechanism of interlayer injection–production coupling can be summarized as reservoir elastic energy adjustment and reservoir flow field reconstruction, based on the established physical model. The application of interlayer injection–production coupling technology can significantly improve the interlayer exploitation differences in strongly heterogeneous sandstone reservoirs. The injection rate, liquid production rate, half-period ratio, and coupling period all have a significant influence on the interlayer injection–production coupling effect. Specifically, for the J1 well group, the injection rate and liquid production rate can be appropriately increased by a factor of 2 and 1.5, and corresponding oil recovery will increase by 6.4% and 5%. Meanwhile, when the half-period ratio increases to 3:1, the oil recovery will increase by 7.08%. Therefore, during the design of the interlayer injection–production coupling scheme, the injection rate and liquid production rate can be appropriately increased, the injection time should be increased for the under-exploitation layer, and the optimal coupling period should be selected based on the characteristics of the oilfield. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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27 pages, 46094 KiB

Open AccessArticle

Study on Hydraulic Fracture Propagation in Mixed Fine-Grained Sedimentary Rocks and Practice of Volumetric Fracturing Stimulation Techniques

by Hong Mao, Yinghao Shen, Yao Yuan, Kunyu Wu, Lin Xie, Jianhong Huang, Haoting Xing and Youyu Wan

Processes 2024, 12(9), 2030; https://doi.org/10.3390/pr12092030 - 20 Sep 2024

Viewed by 491

Abstract

Yingxiongling shale oil is considered a critical area for future crude oil production in the Qaidam Basin. However, the unique features of the Yingxiongling area, such as extraordinary thickness, hybrid sedimentary, and extensive reformation, are faced with several challenges, including an unclear understanding of the main controlling factors for hydraulic fracturing propagation, difficulties in selecting engineering sweet layers, and difficulties in optimizing the corresponding fracturing schemes, which restrict the effective development of production. This study focuses on mixed fine-grained sedimentary rocks, employing a high-resolution integrated three-dimensional geological-geomechanical model to simulate fracture propagation. By combining laboratory core experiments, a holistic investigation of the controlling factors was conducted, revealing that hydraulic fracture propagation in mixed fine-grained sedimentary rocks is mainly influenced by rock brittleness, natural fractures, stress, varying lithologies, and fracturing parameters. A comprehensive compressibility evaluation standard was established, considering brittleness, stress contrast, and natural fracture density, with weights of 0.3, 0.23, and 0.47. In light of the high brittleness, substantial interlayer stress differences, and localized developing natural microfractures in the Yingxiongling mixed fine-grained sedimentary rock reservoir, this study examined the influence of various construction parameters on the propagation of hydraulic fractures and optimized these parameters accordingly. Based on the practical application in the field, a “three-stage” stimulation strategy was proposed, which involves using high-viscosity fluid in the front to create the main fracture, low-viscosity fluid with sand-laden slugs to create volume fractures, and continuous high-viscosity fluid carried sand to maintain the conductivity of the fracture network. The resulting oil and gas seepage area corresponding to the stimulated reservoir volume (SRV) matched the actual well spacing of 500 m, achieving the effect of full utilization. The understanding of the controlling factors for fracture expansion, the compressibility evaluation standard, and the main process technology developed in this study effectively guide the optimization of transformation programs for mixed fine-grained sedimentary rocks. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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25 pages, 13281 KiB

Open AccessArticle

Dilation Potential Analysis of Low-Permeability Sandstone Reservoir under Water Injection in the West Oilfield of the South China Sea

by Huan Chen, Yanfeng Cao, Jifei Yu, Yingwen Ma, Yanfang Gao, Shaowei Wu, Hui Yuan, Minghua Zou, Dengke Li, Xinjiang Yan and Jianlin Peng

Processes 2024, 12(9), 2015; https://doi.org/10.3390/pr12092015 - 19 Sep 2024

Viewed by 485

Abstract

At present, many offshore oil fields are facing problems, such as pollution-induced near-well zone blockage, poor inter-well connectivity, and strong vertical heterogeneity, which lead to insufficient formation energy and low production in the middle and late stages of development. It is necessary to develop a new technology to overcome these issues. In this regard, water-injection-induced dilation technology, which was already proven to have positive effects on loose sandstone reservoirs, was controversially applied to an offshore low-permeability reservoir. To investigate whether the water-injection-induced dilation technology is suitable, experiments were conducted to analyze the dilation potential of offshore low-permeability sandstone reservoirs, namely, X-ray diffraction, laser particle size analysis, physical simulation, computed tomography scan, and electron microscope scanning experiments. The X-ray diffraction experiments showed that the samples had more than 80% non-clay mineral content and a high brittleness index, which meant more complex microfractures under water injection. Particle size analysis experiments revealed that the particle size was mainly between 10 μm and 100 μm, and thus belonged to coarse silty sand. According to the sorting grade, the sample particle size distribution was uniform and the reservoir was more prone to dilation. The true triaxial physical simulation showed that a volumetric dilation zone occurred around the wellbore, where complicated microfractures occurred. This paper provides adequate evidence and mechanisms of dilation potential for an offshore low-permeability sandstone reservoir. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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12 pages, 3929 KiB

Open AccessArticle

Acid-Etched Fracture Conductivity with In Situ-Generated Acid in Ultra-Deep, High-Temperature Carbonate Reservoirs

by Haizheng Jia, Hongyuan Pu, Jianmin Li, Junchao Wang, Xi Chen, Jianye Mou and Budong Gao

Processes 2024, 12(9), 1792; https://doi.org/10.3390/pr12091792 - 23 Aug 2024

Viewed by 454

Abstract

In situ-generated acid is commonly employed in ultra-deep, high-temperature carbonate reservoirs during acid fracturing to increase the effective acid penetration distance. However, the variation pattern of acid-etched fracture conductivity with in situ-generated acid has not been systematically studied. This paper investigates the evolution of the conductivity of primary and secondary fractures through a series of experiments involving in situ acid displacement and acid-etched fracture conductivity measurement. Based on the experimental results, a calculation model for the conductivity of acid-etched fractures with in situ-generated acid was established. The study indicates that after acid etching, rough particulate points and grooved dissolution patterns form on the surfaces of primary and secondary fractures, respectively. The dissolution volume in primary fractures is greater than that in secondary fractures, with both showing a linear increase over time. Due to the presence of dissolution grooves on the surfaces of secondary fractures, their conductivity is higher than that of primary fractures under the same acid–rock contact time. The conductivity of both primary and secondary fractures increases with the acid–rock contact time. However, beyond approximately 70 min of contact time, the conductivity of primary fractures shows no significant increase. The conductivity of primary and secondary fractures with in situ-generated acid is slightly lower than that with gelled acid under the same contact time, but significantly higher than that with crosslinked acid. This study provides guidance for the design and parameter optimization of acid fracturing in ultra-deep, high-temperature carbonate reservoirs. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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12 pages, 4010 KiB

Open AccessArticle

Improving Shale Stability through the Utilization of Graphene Nanopowder and Modified Polymer-Based Silica Nanocomposite in Water-Based Drilling Fluids

by Yerlan Kanatovich Ospanov, Gulzhan Abdullaevna Kudaikulova, Murat Smanovich Moldabekov and Moldir Zhumabaevna Zhaksylykova

Processes 2024, 12(8), 1676; https://doi.org/10.3390/pr12081676 - 10 Aug 2024

Viewed by 866

Abstract

Shale formations present significant challenges to traditional drilling fluids due to fluid infiltration, cuttings dispersion, and shale swelling, which can destabilize the wellbore. While oil-based drilling fluids (OBM) effectively address these concerns about their environmental impact, their cost limits their widespread use. Recently, nanomaterials (NPs) have emerged as a promising approach in drilling fluid technology, offering an innovative solution to improve the efficiency of water-based drilling fluids (WBDFs) in shale operations. This study evaluates the potential of utilizing modified silica nanocomposite and graphene nanopowder to formulate a nanoparticle-enhanced water-based drilling fluid (NP-WBDF). The main objective is to investigate the impact of these nanoparticle additives on the flow characteristics, filtration efficiency, and inhibition properties of the NP-WBDF. In this research, a silica nanocomposite was successfully synthesized using emulsion polymerization and analyzed using FTIR, PSD, and TEM techniques. Results showed that the silica nanocomposite exhibited a unimodal particle size distribution ranging from 38 nm to 164 nm, with an average particle size of approximately 72 nm. Shale samples before and after interaction with the graphene nanopowder WBDF and the silica nanocomposite WBDF were analyzed using scanning electron microscopy (SEM). The NP-WBM underwent evaluation through API filtration tests (LTLP), high-temperature/high-pressure (HTHP) filtration tests, and rheological measurements conducted with a conventional viscometer. Experimental results showed that the silica nanocomposite and the graphene nanopowder effectively bridged and sealed shale pore throats, demonstrating superior inhibition performance compared to conventional WBDF. Post adsorption, the shale surface exhibited increased hydrophobicity, contributing to enhanced stability. Overall, the silica nanocomposite and the graphene nanopowder positively impacted rheological performance and provided favorable filtration control in water-based drilling fluids. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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17 pages, 7250 KiB

Open AccessArticle

Study on the Adaptability Evaluation of Micro-Dispersed-Gel-Strengthened-Alkali-Compound System and the Production Mechanism of Crude Oil

by Teng Wang, Tianjiang Wu, Yunlong Liu, Chen Cheng and Guang Zhao

Processes 2024, 12(5), 871; https://doi.org/10.3390/pr12050871 - 26 Apr 2024

Viewed by 977

Abstract

A novel micro-dispersed-gel (MDG)-strengthened-alkali-compound flooding system was proposed for enhanced oil recovery in high-water-cut mature oilfields. Micro-dispersed gel has different adaptability and application schemes with sodium carbonate and sodium hydroxide. The MDG-strengthened-alkali flooding system can reduce the interfacial tension to an ultra-low interfacial-tension level of 10⁻² mN/m, which can reverse the wettability of rock surface. After 30 days aging, the MDG-strengthened-Na₂CO₃ flooding system has good viscosity retention of 74.5%, with an emulsion stability of 79.13%. The enhanced-oil-recovery ability of the MDG-strengthened-Na₂CO₃ (MDGSC) flooding system is 43.91%, which is slightly weaker than the 47.78% of the MDG-strengthened-NaOH (MDGSH) flooding system. The crude-oil-production mechanism of the two systems is different, but they all show excellent performance in enhanced oil recovery. The MDGSC flooding system mainly regulates and seals micro-fractures, forcing subsequent injected water to enter the low-permeability area, and it has the ability to wash the remaining oil in micro-fractures. The MDGSH flooding system mainly removes the remaining oil on the rock wall surface in the micro-fractures by efficient washing, and the MDG particles can also form weak plugging of the micro-fractures. The MDG-strengthened-alkali flooding system can be used as an alternative to enhance oil recovery in high-water-cut and highly heterogeneous mature oilfields. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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22 pages, 22304 KiB

Open AccessArticle

Study on Fracture Propagation Rules of Shale Refracturing Based on CT Technology

by Jialiang Zhang, Xiaoqiong Wang, Huajian Xiao, Hongkui Ge and Jixiang He

Processes 2024, 12(1), 131; https://doi.org/10.3390/pr12010131 - 3 Jan 2024

Cited by 1 | Viewed by 1570

Abstract

Reactivating oil and gas wells, increasing oil and gas production, and improving recovery provide more opportunities for energy supply especially in the extraction of unconventional oil and gas reservoirs. Due to changes caused by well completion and production in pore pressure around oil and gas wells, subsequently leading to changes in ground stress, and the presence of natural and induced fractures in the reservoir, the process of refracturing is highly complex. This complexity is particularly pronounced in shale oil reservoirs with developed weak layer structures. Through true triaxial hydraulic fracturing experiments on Jimsar shale and utilizing micro-CT to characterize fractures, this study investigates the mechanisms and patterns of refracturing. The research indicates: (1) natural fractures and the stress states in the rock are the primary influencing factors in the fracture propagation. Because natural fractures are widely developed in Jimsar shale, natural fractures are the main influencing factors of hydraulic fracturing, especially in refracturing, the existing fractures have a greater impact on the propagation of secondary fracturing fractures. (2) Successful sealing of existing fractures using temporary blocking agents is crucial for initiating new fractures in refracturing. Traditional methods of plugging the seam at the root of existing fractures are ineffective, whereas extensive injection of blocking agents, forming large “sheet-like” blocking bodies in old fractures, yields better sealing effects, promoting the initiation of new fractures. (3) Moderately increasing the pumping rate and viscosity of fracturing fluid is advantageous in forming “sheet-like” temporary blocking bodies, enhancing the complexity of the network of new fractures in refracturing. (4) When there is a high horizontal stress difference, after sealing old fractures, the secondary hydraulic fractures initiate parallel to and extend from the old fractures. In cases of low horizontal stress difference, the complexity of secondary hydraulic fractures increases. When the horizontal stress changes direction, the secondary hydraulic fractures also change direction. It is recommended to use high-viscosity fracturing fluid and moderately increase the pumping rate, injecting blocking agents to seal old fractures, thereby enhancing the complexity of the network of refracturing. These findings provide important technical guidance for improving the efficiency of shale oil reservoir development. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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17 pages, 8926 KiB

Open AccessArticle

The Characteristics of Fracturing Fluid Distribution after Fracturing and Shut-In Time Optimization in Unconventional Reservoirs Using NMR

by Xin Huang, Lei Wang, Nan Wang, Ming Li, Shuangliang Wu, Qun Ding, Shucan Xu, Zhilin Tuo and Wenqiang Yu

Processes 2023, 11(8), 2393; https://doi.org/10.3390/pr11082393 - 9 Aug 2023

Cited by 1 | Viewed by 840

Abstract

Post-fracturing shut-in, as an important means of improving the energy efficiency of fracturing fluid, has been widely used in the development process of unconventional reservoirs. The determination of the shut-in duration is key to the effectiveness of shut-in measures. However, the distribution characteristics of the fracturing fluid during the post-fracturing shut-in period in unconventional reservoirs, such as the Chang 7 reservoir, were not clear, and the shut-in duration needed further optimization. Therefore, this paper employed low-field nuclear magnetic resonance (NMR) technology to study the distribution characteristics of the fracturing fluid during the post-fracturing shut-in period in unconventional reservoirs and optimized the shut-in duration. The study showed that the Chang 7 reservoir had a complex pore structure and relatively low porosity and permeability. During the shut-in process, the filtrate was distributed in pore throats with radii ranging from 0.0012 μm to 0.025 μm. Pore throats with radii ranging from 0.003 μm to 0.07 μm acted as dynamic pore throats in the process of imbibition displacement. When the shut-in duration for the Chang 7 segment was 7 days, the growth rate of the retained volume of fracturing fluid filtrate was the highest. When the shut-in duration was 10 days, there was no oil displacement in the medium and large pores, and the retained volume of filtrate was lower than that at 7 days shut-in, indicating that an optimal shut-in duration would be 7 days. This study can provide theoretical and technical support for the development of unconventional reservoirs. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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15 pages, 2913 KiB

Open AccessArticle

Enhanced Oil Recovery and CO₂ Storage Performance in Continental Shale Oil Reservoirs Using CO₂ Pre-Injection Fracturing

by An Zhang, Yalin Lei, Chenjun Zhang and Jiaping Tao

Processes 2023, 11(8), 2387; https://doi.org/10.3390/pr11082387 - 8 Aug 2023

Cited by 1 | Viewed by 1938

Abstract

CO₂ pre-injection fracturing is a promising technique for the recovery of continental shale oil. It has multiple advantages, such as oil recovery enhancement, CO₂ geological storage and water consumption reduction. Compared with conventional CO₂ huff and puff and flooding, CO₂ pre-injection features higher injection rates and pressures, leading to EOR and improved CO₂ storage performance. Combining physical experiments and numerical simulation, this research systematically investigated the EOR and storage performance of CO₂ pre-injection in continental shale reservoirs. The results showed that CO₂ pre-injection greatly improved the oil recovery; after seven cycles of soaking, the average oil recovery factor was 39.27%, representing a relative increase of 31.6% compared with that of the conventional CO₂ huff and puff. With the increasing pressure, the CO₂ solubility grew in both the oil and water, and so did the CO₂ adsorption in shale. Numerical simulation indicated that the average CO₂ storage ratio of the production stage was 76.46%, which validated the effectiveness of CO₂ pre-injection in terms of CO₂ geological storage. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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15 pages, 5963 KiB

Open AccessArticle

Automatic Optimization of Multi-Well Multi-Stage Fracturing Treatments Combining Geomechanical Simulation, Reservoir Simulation and Intelligent Algorithm

by Bo Wang, Yan Fang, Lizhe Li and Zhe Liu

Processes 2023, 11(6), 1759; https://doi.org/10.3390/pr11061759 - 9 Jun 2023

Cited by 2 | Viewed by 1323

Abstract

Shale reserves have become an ever-increasing component of the world’s energy map. The optimal design of multi-well multi-stage fracturing (MMF) treatments is essential to the economic development of such resources. However, optimizing MMF treatments is a complex process. It requires geomechanical simulation, reservoir simulation, and automatic optimization. In this work, an integrated workflow is proposed to optimize MMF treatments in an unconventional reservoir, and the net present value (NPV) of reserves was treated as the objective function. The forward model consists of two submodels: a hydraulic fracturing model and a reservoir simulation model. The stochastic simplex approximation gradient (StoSAG) is used with the steepest ascent algorithm to maximize the NPV function. The computational results show that optimizing the fracture design can achieve a 20% higher NPV than that obtained with the field reference case. The drainage area of the optimal design is larger than that of the initial design. The maximum gas production rate increases from 23.75 MMSCF/day to 34.43 MMSCF/day and the maximum oil production rate increases from 497 STB/day to 692 STB/day. Therefore, new optimization paths can accelerate fracture design and help increase well production. This paper innovatively proposes a coupled workflow that can reduce the waste of manpower and improve the optimization results. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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22 pages, 5114 KiB

Open AccessReview

A Scientometric Review on Imbibition in Unconventional Reservoir: A Decade of Review from 2010 to 2021

by Liu Yang, Duo Yang, Chen Liang, Yuxue Li, Manchao He, Junfei Jia and Jianying He

Processes 2023, 11(3), 845; https://doi.org/10.3390/pr11030845 - 11 Mar 2023

Cited by 1 | Viewed by 1971

Abstract

Spontaneous imbibition is a phenomenon of fluid displacement under the action of capillary force, which is of great significance to reservoir protection, enhanced oil recovery, flow-back optimization, and fracturing fluid selection in unconventional oil and gas reservoirs. Remarkable progress has been made in the imbibition research of oil and gas, and the overall research situation of research needs to be analyzed more systematically. This paper aims to provide a scientometric review of imbibition studies in unconventional reservoirs from 2010 to 2021. A total of 1810 papers are collected from the Web of Science Core Correction database based on selected keywords and paper types. Using CiteSpace software, a quantitative scientific analysis is carried out on the main aspects of national cooperation, institutional cooperation, scholarly cooperation, keyword co-occurrence, journal co-citation, article co-citation, and keyword clustering. The principal research countries, institutions, scholars, keywords, published journals, influential articles, and main research clusters are obtained, and the cooperation relationship is analyzed from the centrality and number of publications. At the end of the paper, the existing knowledge areas are discussed based on the analysis of scientometric results. This study constructs a comprehensive research knowledge map of imbibition, providing relevant research with a more valuable and in-depth understanding of the field. Full article

(This article belongs to the Special Issue Phase Change, Interphase Coupling, and Multiphase Transport in Porous Structures)

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